AGA Financial Forums2.q4cdn.com/766046337/files/doc_presentations/...11 AGA Financial Forum –May 15‐17, 2011 a September , (1) At March 31, 2011, Comprehensive Shareholders’

AGA Financial ForumMay 15‐17, 2011

Safe HarborFor Forward Looking Statements

This presentation may contain “forward‐looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans,performance and capital structure, anticipated capital expenditures and completion of construction projects, as well as statements that are identified by the use of the words “anticipates,”“estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward‐looking statements involve risks anduncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward‐looking statements. The Company’s expectations, beliefs and projectionscontained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achievedor accomplished.

ddi i h f h f ll i i f h ld l l diff i ll f l f d i h f d l ki fi i l dIn addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward‐looking statements: financial andeconomic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures andother investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, includingglobal, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of theCompany’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severeweather, pest infestation or other natural disasters; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves,including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering,processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws and regulations top g p p y, g pp p , p g ; g gwhich the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such ashydraulic fracturing; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; significant changesin market dynamics or competitive factors affecting the Company’s ability to retain existing customers or obtain new customers; changes in demographic patterns and weather conditions;changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments; impairments under the SEC’s full costceiling test for natural gas and oil reserves; changes in the availability and/or cost of derivative financial instruments; changes in the price differential between similar quantities of natural gas atdifferent geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similarquantities of oil or natural gas having different quality, heating value, geographic location or delivery date; changes in the projected profitability of pending or potential projects, investments ort ti i ifi t diff b t th C ’ j t d d t l it l dit d ti d l h i t l ith t t th C ’transactions; significant differences between the Company’s projected and actual capital expenditures and operating expenses; delays or changes in costs or plans with respect to the Company’sprojects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation ofinterconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving derivatives, acquisitions, financings, rate cases (which address, amongother things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipatedimpacts of restructuring initiatives in the natural gas and electric industries; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrateexisting and any subsequently acquired business or properties; changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’spension and other post‐retirement benefits, which can affect future funding obligations and costs and plan liabilities; significant changes in tax rates or policies or in rates of inflation or interest;significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; changes ing g p y p p y p p g g gaccounting principles or the application of such principles to the Company; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns toeffect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post‐retirement benefits; or increasingcosts of insurance, changes in coverage and the ability to obtain insurance.

Forward‐looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, canbe estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gasquantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimatesother than proved reserves are subject to substantially greater risk of being actually realized Investors are urged to consider closely the disclosure in our Form 10 K available at

2 AGA Financial Forum – May 15‐17, 2011

other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10‐K available atwww.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov.

For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward‐looking statements, see “Risk Factors” inthe Company’s Form 10‐K for the fiscal year ended September 30, 2010 and the Company’s Forms 10‐Q for the periods ended December 31, 2010 andMarch 31, 2011. The Company disclaims anyobligation to update any forward‐looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.

National Fuel Gas CompanyBusiness Segment Reporting

Publicly Traded National Fuel Gas Company

yHolding CompanyNYSE symbol ‐ NFG

iExploration & Production

Pipeline & Storage Utility Energy

MarketingReporting Segments

Seneca Resources Corporation

National Fuel Gas Supply Corporation

National Fuel Gas Distribution

CorporationNational Fuel

Resources, Inc.Operating

Subsidiaries

Empire Pipeline, Inc.


National Fuel Gas CompanyOur Businesses

Utility

Pipeline & Storage

Exploration & ProductionpAppalachia, California, Gulf of Mexico

Energy Marketinggy g

Midstream

SawmillsSawmills

Landfill Gas

Gas Fired Generation


Gas‐Fired Generation




National Fuel Gas CompanyNet Income from Continuing Operations

Excluding Items Impacting Comparability (1)

$266 3$300

$266.3

$210.5 $219.1

$200

P&S$33.4 MM15.4%

$146.6

$98.0 $112.5

$200

$ Millions)

Utility$62.3 MM28 6%

E&P$116.0 MM

53.3%

$61.5 $58 7 $62.5

$54.1 $47.4 $36.7$100($ 28.6%

$61.5 $58.7 $62.5

$0

2008 2009 2010Fiscal Year Ended

$217.8 MillionTwelve Months Ended


(1) A reconciliation to GAAP Net Income is included at the end of this presentation.

Utility P&S E&P Mktg, Corp & All Other

Twelve Months EndedMarch 31, 2011

National Fuel Gas CompanyCapital Expenditures(1) from Continuing Operations

$1,250 Utility Pipeline & Storage Exploration & Production All Other

$780‐895$845‐1,010$1,000

Millions)

$600‐655$685‐800

$417$501

$500

$750

nditures ($

M

$166 $100 150 $100 135$147

$192

$188

$398

$600‐655

$248

$417

$307

$250

$500

Capital Expe

$54 $57 $56 $58 $55‐60 $55‐60$43

$166$53 $38

$100‐150 $100‐135

$0

2007 2008 2009 2010 2011 Forecast

2012 Forecast


Forecast ForecastFiscal Year

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

National Fuel Gas Company

$1,250 Appalachian Growth ‐ E&P Appalachian Growth ‐ Infrastructure Other Spending

Capital Expenditures(1) – An Appalachian Focus(2) (3)

$115‐140$780‐895$845‐1,010$1,000

Millions)

$95‐110

$85‐120$120‐180

$

$417$501

$500

$750

nditures ($

M

$356

$565‐605$645‐750

$208

$351 $161

$129

$248

$417

$307

$250

$500

Capital Expe

$39 $66$139

$208

$0

2007 2008 2009 2010 2011 Forecast

2012 Forecast


Forecast ForecastFiscal Year

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.(2) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.(3) Any other maintenance spending in the Appalachian region, plus spending in areas outside of the Appalachian region.

National Fuel Gas CompanyShort‐Term Debt

2%

Capital Structure

Sh h ld ’

Long‐Term DebtLong‐Term

Debt Shareholders’ Equity

63%

35%Shareholders’ Equity63%

Debt37%

$2.866 Billion(1)

at March 31, 2011

Forecasted Capital Structure(2)

t S t b 30 2011


at September 30, 2011(1) At March 31, 2011, Comprehensive Shareholders’ Equity, Long‐Term Debt and the Current Portion of Long‐Term Debt totaled $2.866 Billion as presented on the Company’s Balance Sheet, of which $0.899 Billion was Long‐

Term Debt, $0.150 Billion was the Current Portion of Long‐Term Debt and $1.817 Billion was Comprehensive Shareholders’ Equity (2) At September 30, 2011, forecasted Total Capitalization is $3.014 Billion, of which $0.899 Billion is Long‐Term Debt, $0.150 Billion is the Current Portion of Long‐Term

Debt, $0.044 Billion is Short‐Term Debt and $1.921 Billion is Comprehensive Shareholders’ Equity

National Fuel Gas CompanyDividend Growth

$1.38National Fuel has had 108 uninterrupted f di id d d h i dyears of dividend payments and has increased

its dividend for 40 consecutive years

Compound Annual Growth Rate

5.1%

$0.19

%


Annual Rate at Fiscal Year End

National Fuel Gas CompanyNatural Gas Industry ‐ 5‐Year Total Return

175%

i l l G C h

125%

150% National Fuel Gas Company has consistently generated long‐term total returns that outperform its

natural gas industry peers

75%

100%

r Total R

eturn g y p

d Gas Peers

bution

Peers

Peers

25%

50%5‐Year

NFG

OKE

SJI

OGE

EGAS

NST

EGN

CNP

UGI

Diversifie

dWEC

CMS

GAS

NJR

RGCO

Gas Distrib

XEL

ATO

SWX

CPK

WGL

DTE

NWN

PNY

LNT

STR

DGAS

EQT

TE MGEE

Gas/Elec. P

AGL

LG PCG

TEG

AVA

CHG

VVC

SRE

SUG

SCG

NI

NEW

UTL

PEG

MDU

PNM

AEE

0%

25%


‐25%

Source: Edward Jones – Natural Gas Industry Summary: Quarterly Financial and Common Stock Information for the Quarter Ended March 31, 2011

National Fuel Gas CompanyPeer Group Comparisons

1‐Year Total Return 3‐Year Total Return 5‐Year Total Return1 Year Total ReturnPeer Group Total Return

National Fuel 71%

Utility Peers 39%

3 Year Total ReturnPeer Group Total Return

National Fuel 162%

Utility Peers 56%

5 Year Total ReturnPeer Group Total Return

National Fuel 50%

E&P Peers 37% Utility Peers 39%

Diversified Peers 2%

E&P Peers ‐13%

Utility Peers 56%


E&P Peers 48%

E&P Peers 37%


Utility Peers 19%

National Fuel’s diversified business model continues to generate long‐term outperformance versus its peer groups by g g p f p g p ylimiting downside risk through economically challenging times

and capturing upside growth in an expanding market


All returns are for the period starting at the close on April 1, 20XX and ending March 31, 2011. Calculated utilizing Bloomberg L.P. software and peer group averages calculated using an arithmetic mean Diversified Peers: EGN, EP, EQT, MDU, WMB; Utility Peers: AGL, ATO, CPK, NI, NJR, NWN, SWX, WGL; E&P Peers: BRY, CHK, CNX, COG, CRZO, EOG, PETD, PVA, RRC, SFY, SM, SWN, UNT

Utility Segment

N i l F l G Di ib i C i


National Fuel Gas Distribution Corporation

UtilityKeys to Continued Success

Provide Stable Earnings

Operate Safe System Control Costs

Excellent Customer Service

Strong Regulatory Strategy


Utility

$75NY PA

Capital Spending

$ $18 0

$54.4 $54.2$57.5 $56.2 $58.0$60

Millions)

$16.0 $18.1$18.3 $18.4

$18.0

$30

$45

pend

ing ($

$38.4 $36.1 $39.2 $37.8 $40.0$15

$30

Capital Sp

$0

2006 2007 2008 2009 2010


Fiscal Year

Utility

$250NY PA

O&M Expense

$63.8 $63.8 $62.1

$204.3 $203.0 $202.7$191.2

$181.3$200

Millions)

$$60.7

$56.3

$100

$150

xpen

se ($

M

$140.5 $139.2 $140.6 $130.5 $125.0$50

$100

O&M Ex

$0

2006 2007 2008 2009 2010


Fiscal Year

UtilityExcellent Customer Service

C S i P fNY G l

NY A l(1)

PA A l(1)Customer Service Performance Goal Actual(1) Actual(1)

Telephone Response (within 30 seconds) 74.0% 90.0% 89.0%

Customer Satisfaction:ResidentialCommercial

85.1%86.0%

92.2%91.4%

88.5%

PSC Complaints (per 100,000 Customers) 2.1 0.02 N/A

Estimated Meter ReadingNot to Exceed

15.9% 13.1% 9.0%

Adjusted Bills Not to Exceed1 9% 1.0% 1.2%1.9%

New Service Gas Installations Installed within 10 Days

98.0% 99.9% 99.6%

Non‐Emergency Field Appointments Kept 98 0% 99 1% 99 4%


Non‐Emergency Field Appointments Kept 98.0% 99.1% 99.4%

(1) 12‐months ended March 31, 2011

UtilityRate Mechanisms

New York Pennsylvania

Revenue Decoupling

Conservation Incentive Program

y

Low Income Rates

Ch i P /PORConservation Incentive Program

Merchant Function Charge

Low Income Rates

Choice Program/POR

Merchant Function Charge

Pending:90/10 Sharing

Weather Normalization

Pending:

Distribution System Improvement Charge (DSIC)

Choice Program Revenue Decoupling


Utility

20.0 NY PA

Return on Equity (1)

14.013.2

14.715.0

uity (%

)

10.39.1

10.99.8

10.611.8

10.0

urn on

Equ

6.3

5.0

Retu

0.0

2006 2007 2008 2009 2010


(1) Calculated using Average Total Comprehensive Shareholder Equity.

2006 2007 2008 2009 2010

Fiscal Year

UtilityDiluted Earnings per Share(Before Items Impacting Comparability)$1.00

$0.73 $0.73 $0.76$0.75

Share

$0.55(1)$0.60

$0.50

arnings pe

r

$0.25

Dilu

ted Ea

$0.00

2006 2007 2008 2009 2010


(1) Excludes out‐of‐period adjustment to symmetrical sharing of $0.03; Including this adjustment, GAAP earnings would be $0.58.

2006 2007 2008 2009 2010

Fiscal Year

Utility2011

Provide Stable Earnings

Operate Safe System Control Costs

Excellent Customer Service

Strong Regulatory Strategy


Pipeline & Storage / Midstream




National Fuel Gas Midstream Corporation

PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES

NORTHERN ACCESS

EXPANSION

LAMONTCOMPRESSOR

LAMONTCOMPRESSOR

TIOGA COUNTY EXTENSION

EXPANSION

CENTRAL TIOGA COUNTY

COMPRESSORSTATION

PHASE I & II

COVINGTONG G

COMPRESSORSTATION

PHASE I & II

EXTENSION

GATHERINGSYSTEM

TROUT RUNGATHERINGSYSTEMLINE “N”

EXPANSION LINE “N”WEST TO EAST OVERBECK TO

LEIDY

EXPANSION

Seneca Drilling Activity

EOG JV Drilling Activity

LINE “N” 2012

EXPANSION

25W2E Overbeck to Leidy

Northern Access Expansion

Expansion Projects


Exploration & Production

S R C i




600

cf) Natural Gas

Fiscal Year End Proved Reserves(1)

East – AppalachiaR 333 B f (48%)

226 249

428

200

400

ved Re

serves (BReserves: 333 Bcfe (48%)

0

2008 2009 2010

Prov

At September 30

46.2 46.6 45.2

40

60

es (M

Mbb

l)

Oil

West – CaliforniaR 333 B f (47%)

0

20

Proved

ReserveReserves: 333 Bcfe (47%)

(55.5 MMBoe) Gulf of MexicoReserves: 34 Bcfe (5%)

T t l P d R 700 B f


2008 2009 2010At September 30

(1) At September 30, 2010

Total Proved Reserves: 700 Bcfe

Exploration & ProductionHistorical Daily Production

250

West Upper Devonian Gulf Marcellus

200

mcfe/d)

West Upper Devonian Gulf Marcellus

100

150

duction (M

m

50

100

Daily Prod

‐


Exploration & ProductionCapital Expenditures by Region

$1,000 West Upper Devonian Gulf of Mexico Marcellus

$600 655

$685‐800$750

Millions)

$398

$600‐655

$500

nditures ($

M

$332

$560‐600$640‐740

$192 $188

$398

$250

Capital Expen

$63 $31(1) $28 $35‐45 $40‐50

$61$68

$64 $71

$0

Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Fiscal 2012

C

(1)


Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast

Fiscal 2012 Forecast

(1) Does not include the $34.9MM acquisition of Ivanhoe’s US‐based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures.

Exploration & ProductionAnnual Production by Region

83‐100100 West Upper Devonian Gulf of Mexico Marcellus

66‐7180

fe)

Marcellus production in Fiscal 2012 could equal the entire company

7.2 35‐37

58‐71

40.8 42.5 49.7

60

duction (Bcf

p yproduction in Fiscal 2011

7.9 8.7 9.3 7‐9 6‐8

14.1 13.7 13.4 5

20

40

Prod

18.8 20.1 19.8 19‐20 19‐21

0






C lif i


California

Seneca’s California Properties

South Lost Hills~1,830 BOEPD

North Lost Hills~1,235 BOEPDTulare & Etchegoin Formation

Monterey ShalePrimary216 Active Wells

Tulare & Etchegoin FormationPrimary & Steamflood181 Active Wells

North Midway SunsetNorth Midway Sunset~4,050 BOEPDPotter & Tulare FormationSteamflood703 Active Wells

Sespe~990 BOEPDSespe FormationPrimary

South Midway Sunset~680 BOEPD Primary

193 Active WellsAntelope FormationSteamflood81 Active Wells


As of March 27, 2011

CaliforniaAverage Daily Production

10,000 Modest capital spending to maintain production

Pursue additional bolt‐on 9,500

0,000

acquisitions

2011 Plans: CapEx ‐ $40 MM

8,500

9,000

OE/Day

p $

50 Development wells

Two 5‐acre in‐fill wells at Sespe7,500

8,000

B

7,000


CaliforniaFiscal Year 2011 Sespe Field Development Plans

d ll fFirst drilling for Seneca at Sespe since 1991

Will drill six wells during this fiscal year

Wells to be drilled at 10‐acre spacing: 4 wells

Test wells to be drilled at 5‐acre spacing: 2 wellsp g

If successful, 5‐acre down‐spacing could add substantial new reserves and resource potentialp



E Di i i


East Division

East DivisionAverage Daily Production

150

100

125

Mcfe/Day) Upper Devonian Marcellus

75

100

rodu

ction (M

M

Rapid growth in the East Division as Marcellus is ramping up

25

50

erage Daily Pr ramping up

0

Ave


Marcellus ShaleSeneca’s Pennsylvania Acreage

Seneca Resource Acreage Position745,000 Net Acres in the heart of the PA Marcellus fairwayyRisked Resource Potential: 8‐15 TCFE80% Fee – Seneca owns the minerals No lease expiration

94% Average NRI SRC L A

SRC Fee Acreage


94% Average NRI SRC Lease Acreage

Marcellus ShaleSeneca’s Development Areas

Eastern Development Area (Mostly Leased)

Western Development AreaWestern Development Area(Mostly Fee and HBP)

SRC L A

SRC Fee Acreage


SRC Lease Acreage

Marcellus ShaleEastern Development Area

Covington Area – Full DevelopmentDCNR Block 001 43 Wells Drilled; 24 Producing (3 Shut‐In)Gross Prod: (As of 5/10/11): 90 MMCFD

1st Marcellus Well IP: 4.5 MMCFD1st Geneseo Test IP: ~3 MMCFD

DCNR Block 007 1st Well IP: 2.1 MMCFD

DCNR Block 595 – Full Development4 Wells Drilled; 4 ProducingG P d (A f 5/10/11) 12 MMCFD

Tioga/Lycoming/Potter55,000 AcresPotential: 2 Tcf

DCNR Block 100 1st W ll IP 15 8 MMCFDSRC L A

SRC Fee Acreage

Gross Prod: (As of 5/10/11): 12 MMCFD


1st Well IP: 15.8 MMCFD2011: 6 Wells PlannedFirst Production: Fall 2011

SRC Lease Acreage

Marcellus ShaleLonger Lateral EDA Wells Outpacing 6 Bcf Typecurve

8,000Average EDA Production per Well

6 B f T

(1)

6,000

6 Bcf Typecurve

4,000

Rate (M

cf/d)

2,000

Gas

0

0 30 60 90 120 150 180 210 240 270 300 330 360


0 30 60 90 120 150 180 210 240 270 300 330 360

Days(1) Chart data represents horizontal well production from wells with lateral lengths greater than 3,500 feet

Marcellus ShaleWestern Development Area ‐ Activity

SRC Lease Acreage

SRC Fee AcreageApprox. Outline of JV Acreage

200 000 Gross Acres

EOG Contributed JV Acreage

SRC Contributed JV Acreage200,000 Gross AcresSeneca 50% W.I. (Avg. 58% NRI)

Owl’s Nest AreaOwl s Nest AreaSeneca Operated2 New Wells CompletedIP Rates: 4.0 – 4.5 MMCFD

Beechwood AreaSeneca Operated3 Wells Drilled

Seneca Operated

EOG O d

Punxy Area – Full DevelopmentEOG Operated39 Wells Drilled; 25 ProducingGross Production (As of 5/10/11): 45 MMCFD


EOG Operated( / / )

2011: 30+ Wells Planned

Marcellus ShaleTarget Zone Example

Important to Find Ideal TargetMust account for the variable rock quality and geomechanicalprofile

MarcellusInterval

Major factor in quality of Fracture Stimulation

Optimal Target Zone


Zone

Marcellus Shale

150

EOG JV Eastern Development Area Western Development Area

Marcellus Net Production

100

125

n (M

Mcfe)

75

00

y Net Produ

ction

Seneca Operated

25

50

Marcellu

s Daily

‐

25 EOG JV


Marcellus ShaleCentralized Water System

Recovering water discharged from an b d d l i hi h d labandoned coal mine which was adversely impacting a local trout stream

Authorized by SRBC to withdraw approximately 500,000 gallons per day of mine discharge

Water pipeline system supplies frac water for Seneca in Tioga County (90 wells)

Can supply water for 3 fracs per monthCan supply water for 3 fracs per month

System Cost: ~$3.7 Million

Cost Savings: ~$120,000 per well

Pay Out: 31 WellsPay Out: 31 Wells

Other Benefits: Improved stream qualitySubstantial reduction of water truck activity


activityNo need to withdraw water elsewhere

Utica Shale

SenecaSeneca Acreage


Source rock maturation status based on combined CAI to Ro regression equation. (Trenton‐Black River Research Consortium, 2006)

Seneca ResourcesEvaluation of JV Opportunities

Seneca’s Marcellus joint venture goals:

Ramp up development faster than current growth plans

Bring forward the earnings stream, where a minority‐interest partner pays a significant portion of the early drilling costs enhancing shareholder valuesignificant portion of the early drilling costs, enhancing shareholder value

Continue operating across most of its acreage position

Seneca continues to have active and ongoing discussions with potential jointSeneca continues to have active and ongoing discussions with potential joint venture partners

Seneca has received serious offers

Anticipate reaching a conclusion by the end of June

Seneca will only consider joint venture opportunities that management believes will enhance shareholder value


believes will enhance shareholder value

National Fuel Gas CompanyKey Takeaways

High‐Quality Marcellus Acreage Positiong Q y g745,000 net acres with a resource potential of 8‐15 Tcfe Fee ownership results in superior economicsRapid Growth: 0 – 120 MMCFD in 18 months

Balanced Business ModelRegulated segments support dividend and are not sensitive to commodity pricesSizable oil production provides earnings stability

S Fi i l P i iStrong Financial PositionSimple balance sheetWell capitalizedSi ifi t i t ll t d h fl


Significant internally generated cash flows



National Fuel Gas Company

Corporate & Financial Highlights


Corporate & Financial Highlights

National Fuel Gas CompanyFiscal Year 2011 Earnings Guidance – Key Drivers(1)

Exploration & ProductionP d i ↑ 38%

FY 2011

• Production ‐ ↑ 38%• DD&A: $2.17 Area per Mcfe• LOE: $0.95 to $1.05 per Mcfe• G&A: $41 ‐ $44 Million

FY 2011 GAAP EPS

$2.83 to

Pipeline & Storage• Operating Expense: ↑ 3% to 5%• Transportation Revenue: ↓ $7.5 Million• Project Development Costs (O&M): $7 Million

FY2010 Operating Results + =

to $2.98Utility

• Operating Expense: ↑ 3% to 5% • PA Normal Weather

$2.65(2)

Corporate & All Other • Sale of Horizon Power, Inc. Investments: $0.38/Sh• Midstream Earnings per Share: $0.05 to $0.10


NYMEX Pricing: Gas: $4.00/MMBtu ⏐ Oil: $80.00/Bbl(1) The Earnings Guidance is current as of May 5, 2011(2) Excludes gain on disposal of discontinued operations of $0.07 and earnings from discontinued operations of $0.01; including these items GAAP earnings were $2.73.

National Fuel Gas CompanySeneca Oil and Gas Hedge Positions

Natural Gas Volume Average Volume AverageNatural Gas Swaps

Volume(Bcf)

Average Hedge Price

Fiscal 2011 14.6 $6.05 / Mcf

Fiscal 2012 35 0 $5 89 / Mcf

Oil SwapsVolume(MMBbl)

Average Hedge Price

Fiscal 2011 0.9 $70.93 / Bbl

Fiscal 2012 1 6 $77 03 / BblFiscal 2012 35.0 $5.89 / Mcf

Fiscal 2013 23.9 $5.67 / Mcf

Fiscal 2014 4.6 $5.89 / Mcf

Fiscal 2012 1.6 $77.03 / Bbl

Fiscal 2013 0.9 $86.21 / Bbl

Fiscal 2014 0.2 $94.90 / Bbl

For fiscal year 2011, Seneca has hedged

NYMEX Strip Prices(at 05/11/11)

Natural Gas Oil

Fi l 2011(1) $4 11 $92 97 Seneca has hedged 58% of its remaining forecasted production

Fiscal 2011(1) $4.11 $92.97

Fiscal 2012 $4.72 $99.15

Fiscal 2013 $5.16 $96.79


Fiscal 2014 $5.52 $94.93

(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 through May 2011 contracts.

Pipeline & Storage / Midstream




National Fuel Gas Midstream Corporation

PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES

NORTHERN ACCESS

EXPANSION

LAMONTCOMPRESSOR

LAMONTCOMPRESSOR

TIOGA COUNTY EXTENSION

EXPANSION

CENTRAL TIOGA COUNTY

COMPRESSORSTATION

PHASE I & II

COVINGTONG G

COMPRESSORSTATION

PHASE I & II

EXTENSION

GATHERINGSYSTEM

TROUT RUNGATHERINGSYSTEMLINE “N”

EXPANSION LINE “N”WEST TO EAST OVERBECK TO

LEIDY

EXPANSION

Seneca Drilling Activity

EOG JV Drilling Activity

LINE “N” 2012

EXPANSION

54W2E Overbeck to Leidy

Northern Access Expansion

Expansion Projects


Pipeline & Storage/MidstreamExpansion Initiatives

Project NameCapacity (Dth/D)

Est.CapEx

In‐ServiceDate

Market Status

Covington Gathering System

145,000 $16 MM 11/17/09 Fully Subscribed Completed – Flowing into TGP 300 Line

Lamont Compressor Station 40,000 $6 MM 6/15/10 Fully Subscribed Completed – Flowing into TGP 300 Line

Lamont Phase II Project 50 000 $7 6 MM ~ 07/2011 Fully Subscribed Construction began March 2011Lamont Phase II Project 50,000 $7.6 MM ~ 07/2011 Fully Subscribed Construction began March 2011

Line “N” Expansion 160,000 $20 MM ~ 09/2011 Fully Subscribed Construction began February 2011

Tioga County Extension 350,000 $49 MM ~ 09/2011 Fully Subscribed Certificate expected in May

Trout Run Gathering System

300,000 $35 MM Fall 2011 85% Subscribed Preliminary work has begun

Northern Access Expansion 320,000 $62 MM ~11/2012 Fully Subscribed Certificate filed in March 2011

Line “N” 2012 Expansion 150,000 $30 MM ~ 11/2012 Fully Subscribed Planned FERC 7(c) filing – June 2011p y ( ) g

West to East ~425,000 $260 MM Late 2013 29% SubscribedPursuing post‐Open Season requests for remaining 300,000 Dth/day

Central Tioga County Extension

365,000Up to

$135 MM2013/2014

Open Season Closed

Developing facility design and cost estimate


Extension $135 MM 2014 Closed estimate

Pipeline & StorageChallenges & Opportunities

Challenges Opportunities

NFGSC Contract Turnbacks

Supply has received capacity turnbacks on expiring contracts

Expansion Projects

Both Supply and Empire have significant pipeline expansionturnbacks on expiring contracts,

decreasing future revenue by:FY11: ~$7.5 MillionFY12: ~$4‐6 Million

significant pipeline expansion projects planned to transport gas

out of the Marcellus. Yearly revenue from these expansion

Empire Unsold Capacity

~100 000 Dth/d of capacity

projects is forecasted to total:FY11: ~$0.2 MillionFY12: ~$32.0 Million

100,000 Dth/d of capacity remains unsold after the construction of the Empire

Connector in 2008


Midstream CorporationTrout Run Gathering System – Lycoming County

Capacity: 300,000 Dth/d

Will Interconnect with TranscoWill Interconnect with Transco Pipelines in Lycoming County

Seneca Resources will be the anchor shipper

Estimated In‐Service: Fall 2011

Interstate PipelineTransco


Gathering System


S R C i



Marcellus ShalePennsylvania Acreage Holdings

SRC Lease Acreage

SRC Fee Acreage

SRC Contributed JV Acreage


EOG Contributed JV Acreage

Marcellus ShaleDecline Curve – 6.0 BCF Estimated Ultimate Recovery (EUR)

8,000 Category Type Curve Parameters

Initial Rate 7 250 MCF/D

6,000

7,000

MCF/D

Initial Rate 7,250 MCF/D

Average first year decline 72%

Final decline 6%

Hyperbolic Coefficient 1.4

4,000

5,000

Mcf/d

yp

Abandonment rate 60 MCF/D

Average first month rate 6,670 MCF/D

Average first year rate 3,560 MCF/D

2,000

3,000 EUR 6.0 BCF

0

1,000


Marcellus ShalePre‐Tax IRR Comparison at NYMEX of $4.00/MMBtu

Net Net Well Costs ($ Millions)

Eastern Development Area

Description EUR

Net Working Interest

Net Revenue Interest

Well Costs ($ Millions)

$6.0 $6.4

Seneca – EDA Well 8 Bcf 100% 85% 73% 63%

Seneca – EDA Well 6 Bcf 100% 85% 40% 34%

N N

Western Development Area

Description EUR

Net Working Interest

Net Revenue Interest

Well Costs ($ Millions)

$5.0 $6.0

Seneca – EOG JV Well 4 Bcf 50% 60% 44% 29%

Seneca – WDAWell 4 Bcf 100% 100% 28% 19%

Seneca is in active development within the Eastern Development Area. It is currently testing various well and completion designs in its Western Development Area and


testing various well and completion designs in its Western Development Area and expects to see results continue to improve over time.

Marcellus Shale

150EOG JV Horizontal Wells Seneca Horizontal Wells

Gross Horizontal Wells Drilled per Year

115‐140125

150Marcellus Horizontal Rig CountCurrent Rig Count:

Seneca : 4 RigsEOG : 2 Rigs

80‐95

85‐110

75

100

ells Drilled

g

Additional Seneca Rigs Scheduled:5th Rig: Summer 20116th Rig: Fall 2011

29

60‐7558

50

Gross W

e

1129 25‐35

35‐456

14

0

25





Marcellus ShaleTransportation Capacity

Eastern Development AreaCovington Gathering System: 150,000 Dth/d into TGP 300Covington Gathering System: 150,000 Dth/d into TGP 300

Provides capacity for DCNR Tract 595 and Covington in Tioga county

Firm sales of 100,000 Dth/d thru October 31, 2011

Trout Run Gathering System: 200 000 – 250 000 Dth/d into Transco (In Service: Fall 2011)Trout Run Gathering System: 200,000 – 250,000 Dth/d into Transco (In‐Service: Fall 2011)

Provides capacity for DCNR Tract 100 in Lycoming county

Tennessee Gas Pipeline: 50,000 Dth/d of firm capacity to Niagara

P id it f C i t DCNR T t 595 d DCNR T t 007Provides capacity for Covington, DCNR Tract 595 and DCNR Tract 007

Western Development AreaNational Fuel Gas Supply Corporation: ~100,000 Dth/d through 2013 (As of November 2011 )

Provides capacity to acreage in Elk, Cameron, McKean and Potter counties

Supply’s West to East project will create additional capacity in 2013 and beyond

Seneca continues to pursue long‐term firm capacity and sales contracts on many of the


p g p y yinterstate pipeline networks running throughout the Marcellus region

National Fuel Gas Companybl lComparable GAAP Financial Measure

Slides and Reconciliations

This presentation contains certain non‐GAAP financial measures. For pagesthat contain non‐GAAP financial measures, pages containing the most directlycomparable GAAP financial measures and reconciliations are provided in theslides that follow.

The Company believes that its non‐GAAP financial measures are useful toinvestors because they provide an alternative method for assessing theCompany’s operating results in a manner that is focused on the performanceof the Company’s ongoing operations. The Company’s management usesthese non GAAP financial measures for the same purpose and for planningthese non‐GAAP financial measures for the same purpose, and for planningand forecasting purposes. The presentation of non‐GAAP financial measuresis not meant to be a substitute for financial measures prepared in accordancewith GAAP


with GAAP.

Reconciliation of GAAP Net Income to Income From Continuing OperationsExcluding Items Impacting ComparabilityExcluding Items Impacting Comparability($ Thousands) 12 Mos. Ended

FY 2008 FY 2009 FY 2010 3/31/2011GAAP Net Income

E&P Segment GAAP Net Income 146,612$ (10,238)$ 112,531$ 116,040$ P&S Segment GAAP Net Income 54,148 47,358 36,703 33,434 Utility Segment GAAP Net Income 61,472 58,664 62,473 62,258 Marketing Segment GAAP Net Income 5,889 7,166 8,816 8,985 Corporate & All Other GAAP Net Income 607 (2,242) 5,390 34,424 Total GAAP Net Income 268,728$ 100,708$ 225,913$ 255,141$

Discontinued Operations(Income) Loss from Operations, Net of Tax (Corporate & All Other) (1,821)$ 2,776$ (470)$ 358$ Gain on Disposal Net of Tax (Corporate & All Other) (6 310) (6 310)Gain on Disposal, Net of Tax (Corporate & All Other) - - (6,310) (6,310) (Income) Loss from Discontinued Operations, Net of Tax (1,821)$ 2,776$ (6,780)$ (5,952)$

Items Impacting ComparabilityGain on sale of turbine (Corporate & All Other) (586)$ -$ -$ -$ Gain on life insurance policies (Corporate & All Other) - (2,312) - - Gain on sale of unconsolidated subsidiaries (Corporate & All Other) - - - (31,418) ( p ) ( , )Impairment of investment partnership (Corporate & All Other) - 1,085 - - Impairment of oil and gas properties (E&P) - 108,207 - - Total Items Impacting Comparability (586)$ 106,980$ -$ (31,418)$

Income from Continuing Operations excluding Items Impacting ComparabilityE&P Segment Operating Income 146,612$ 97,969$ 112,531$ 116,040$ P&S S O i I 4 148 4 3 8 36 03 33 434P&S Segment Operating Income 54,148 47,358 36,703 33,434 Utility Segment Operating Income 61,472 58,664 62,473 62,258 Marketing Segment Operating Income 5,889 7,166 8,816 8,985 Corporate & All Other Operating Income (1,800) (693) (1,390) (2,946) Total Income from Continuing Operations excluding Items Impacting Comparability 266,321$ 210,464$ 219,133$ 217,771$

AGA Financial Forum – May 15‐17, 2011

Reconciliation of Segment Capital Expenditures to Consolidated Capital ExpendituresConsolidated Capital Expenditures($ Thousands)

FY 2011 FY 2012FY 2007 FY 2008 FY 2009 FY 2010 Forecast Forecast

Capital Expenditures from Continuing OperationsExploration & Production Capital Expenditures 146,687$ 192,187$ 188,290$ 398,174$ $600,000-655,000 $685,000-800,000Pipeline & Storage Capital Expenditures 43,226 165,520 52,504 37,894 $100,000-150,000 $100,000-135,000Utility Capital Expenditures 54,185 57,457 56,178 57,973 $55,000-60,000 $55,000-60,000Marketing, Corporate & All Other Capital Expenditures 3,414 1,614 9,829 7,311 $25,000-30,000 $5,000-15,000Total Capital Expenditures from Continuing Operations 247,512$ 416,778$ 306,801$ 501,352$ $780,000-895,000 $845,000-1,010,000

Capital Expenditures from Discountinued Operations

Exploration & Production Capital Expenditures 29,129$ -$ -$ -$ -$ -$ All Other Capital Expenditures 87 131 216 150All Other Capital Expenditures 87 131 216 150 Total Capital Expenditures from Discontinued Operations 29,216$ 131$ 216$ 150$ -$ -$

Plus (Minus) Accrued Capital ExpendituresExploration & Production FY 2010 Accrued Capital Expenditures -$ -$ -$ (55,546)$ -$ -$ Exploration & Production FY 2009 Accrued Capital Expenditures - - (9,093) 9,093 - - Pipeline & Storage FY 2008 Accrued Capital Expenditures - (16,768) 16,768 - - - All Other FY 2009 Accrued Capital Expenditures - - (715) 715 - - Total Accrued Capital Expenditures -$ (16,768)$ 6,960$ (45,738)$ -$ -$

Elimintations -$ (2,407)$ (344)$ -$ -$ -$ Total Capital Expenditures per Statement of Cash Flows 276,728$ 397,734$ 313,633$ 455,764$ $780,000-895,000 $845,000-1,010,000


R ili ti f A l hi G th C it l E dit tReconciliation of Appalachian Growth Capital Expenditures to Consolidated Capital Expenditures($ Millions)

FY 2011 FY 2012FY 2007 FY 2008 FY 2009 FY 2010 Forecast Forecast

Appalachian Growth Capital Expenditures from Continuing Operations1

Exploration & Production Capital Expenditures - East Division 39.1$ 65.8$ 138.6$ 355.7$ $565-605 $645-750p p pPipeline & Storage Appalachian Expansion Capital Expenditures - - - 10.3 $70-80 $80-105Midstream Capital Expenditures - - 7.4 6.5 $25-30 $5-15Total Appalachian Capital Expenditures from Continuing Operations 39.1$ 65.8$ 146.0$ 372.5$ $660-715 $730-870

Other Capital Expenditures from Continuing OperationsExploration & Production Capital Expenditures 107.6$ 126.4$ 49.7$ 42.5$ $35-50 $40-50Pipeline & Storage Capital Expenditures 43 2 165 5 52 5 27 6 $30-70 $20-30Pipeline & Storage Capital Expenditures 43.2 165.5 52.5 27.6 $30-70 $20-30Utility Capital Expenditures 54.2 57.5 56.2 58.0 $55-60 $55-60Marketing, Corporate & All Other Capital Expenditures 3.4 1.6 2.3 0.8 -$ -$ Total Other Capital Expenditures from Continuing Operations 208.4$ 351.0$ 160.7$ 128.9$ $120-180 $115-140

Capital Expenditures from Discountinued OperationsExploration & Production Capital Expenditures 29.1$ -$ -$ -$ -$ -$ All Oth C it l E dit 0 1 0 1 0 2 0 1All Other Capital Expenditures 0.1 0.1 0.2 0.1 Total Capital Expenditures from Discontinued Operations 29.2$ 0.1$ 0.2$ 0.1$ -$ -$

Plus (Minus) Accrued Capital ExpendituresExploration & Production FY 2010 Accrued Capital Expenditures -$ -$ -$ (55.5)$ -$ -$ Exploration & Production FY 2009 Accrued Capital Expenditures - - (9.1) 9.1 - - Pipeline & Storage Accrued Capital Expenditures - (16.8) 16.8 - - - All Other Accrued Capital Expenditures - - (0.7) 0.7 - - Total Accrued Capital Expenditures -$ (16.8)$ 7.0$ (45.7)$ -$ -$

Eliminations - (2.4) (0.3) - - - Total Capital Expenditures per Statement of Cash Flows 276.7$ 397.7$ 313.6$ 455.8$ $780-895 $845-1,010

(1) Defined as spending related to efforts to drill for gather or transport Appalachian sources of natural gas


(1) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.

AGA Financial Forums2.q4cdn.com/766046337/files/doc_presentations/...11 AGA Financial Forum –May 15‐17, 2011 a September , (1) At March 31, 2011, Comprehensive Shareholders’

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